Production of oil from oil bearing earth formations is produced in many cases by the inherent formation pressure of the oil bearing formation. In many cases, however, the oil bearing formation lacks sufficient inherent pressure to force the oil from the formation upwardly through a string of production tubing and to the surface where it will be transported from a wellhead structure by flowlines. The pressure of the production zone might have been depleted, as is the case with many old oil fields. When this occurs, one method of continuing production is to provide mechanical pumping operations. Another popular method for achieving production from inadequately pressured oil bearing formations is the gas-lift method whereby gas is injected into the annulus between the production tubing and casing under controlled conditions. The tubing extending downwardly into the well to the production zone is provided with a plurality of gaslift valves that are positioned in spaced relation along the length of the tubing. Spacing and other characteristics of the gas-lift valves must be established in accordance with the criteria of the particular well involved in order to achieve production at the maximum rate that is produceable from the formation involved. For the reason that no two wells are exactly alike and may involve differences in such parameters as the height of the static liquid column within the well, the static gradient of the load fluid, i.e. liquid between the valves, geothermal temperature, etc., it is virtually a requirement that each gas-lift system for independent wells be separately calculated in order to achieve optimum production. In view of the fact that many hundreds of gas-lift installations have been made, differing design techniques have been established for designing gas-lift systems, and the techniques have progressed or become modified through the passage of time thereby resulting in other more improved techniques.
One of the early techniques for designing gas-lift installations is a technique involving graphical solutions computed by means of formula involving application of the environment of the well to the design criteria that was known at that time. This technique, referred to as the "minimum gradient method," was based on the premise that the unloading rate, i.e. ejection of the liquid column from the well down to the desired depth, was the same as the ultimate producing rate and thus the theory originated that the temperature opposite each valve would not change from one operation to the other. No allowance was made for the relatively cool load fluid nor for a high percentage of oil which loses heat at a much greater rate than water and flows at a temperature approximating geothermal temperature. Although the minimum gradient method or technique for designing gas-lift systems was considered successful, a technique that is presently referred to as the "decreasing gradient method" evolved because of the need for more efficient gas-lift installations. Prior to the decreasing gradient method, the object was to inject gas into the production tubing at the deepest possible point without sacrificing pressure to unload the kill fluid. In other words, the higher the injection gas pressure at a give point of injection (within limits), the more efficient the installation will be in terms of gas usage per fluid produced. Therefore, the trend has always been to design for ultimate operating conditions without allowing for varying temperatures while unloading resulting in valve interference which can present further unloading of the liquid column within the tubing and results in liquid production that is below the maximum production rate of the well.
From another viewpoint, gas-lift operations are based on a force balance between the gas pressure in the annulus defined between the casing and the production tubing and the fluid load in a tubing. The pressure available to cause tubing unloading from one gas-lift valve to the next deepest gas-lift valve in the tubing string can be no more than the reopening pressure of an upper gas-lift valve. If the reopening pressure is based on the highest temperature possible at the level of the upper valve and the temperature is actually less, an upper gas-lift valve can reopen at a lower pressure than is predicted, thereby improperly injecting gas into the tubing string. In this circumstance, as indicated above, the gas pressure that is needed for unloading a deeper valve is simply not available, thus the upper improperly opening valve causes unloading operations to cease before the tubing has been unloaded down to the desired depth.
Prior to development of the minimum gradient method for the design of gas-lift systems, gas-lift valve spacing was based on the following equation: ##EQU1## Calculation of the distance between valves, utilizing Equation 1 is illustrated and discussed on Pages 20-22 of the gas-lift manual of Macco Oil Tool Co., Inc. pertaining to tubing pressure operated intermittent gas-lift design theory. The distance between valves (DBV) is identified simply as the differential pressure between the casing pressure and tubing pressure divided by the static gradient of the load fluid. Therefore, it is obvious through use of the conventional equation that the utilization of gradient curves to estimate tubing pressures at each valve depth is far superior to the previous method of utilizing emperical spacing factors to determine valve spacing. Through utilization of gradient curves, gas-lift systems were enabled to predict gas volume requirements which then led to the use of varying port sizes for better control of the injection gas. The former technique involved the use of standard port sizes (usually 1/4 inch and 5/16 inch) without regard to gas passage.
From the beginning established by calculations based on Equation 1, the minimum gradient method or technique was a logical progression and became a valuable tool to design engineers involved with design of gas-lift systems. The following illustrations show the design technique established by the minimum gradient method for gas-lift design. It should be noted that all design techniques are based on unloading of the well to a predetermined depth. FIGS. 12-15, which illustrate the prior art, each show a schematic at the left portion of the figure depicting a well having a gas-lift system installed therein with a corresponding depth versus pressure plot in graphical form on the right which should closely approximate the results if a pressure survey were taken at that particular stage of unloading. As shown in FIG. 12, fluid from the casing C is being transferred into the tubing T through all of the valves which are all open due to the hydrostatic head of the fluid within the casing. As shown, gas is being injected into the annulus between the casing and tubing by means of an injection conduit I and is being forced upwardly through the production tubing to the surface by the force generated by the injected gas applied to the annulus. The gradient in the tubing in this situation is equal to the zero GLR (gas liquid ratio) curve (all liquid) for the rate being unloaded. The gas liquid ratio is typically read in cubic feet per barrel from a depth-pressure traverse for a particular size of production tubing. It should be noted that the differential pressure indicated by Delta P indicated at the right side of the graphical representation in the figures is not to be misconstrued as the differential pressure that is reponsible for spacing the gas-lift valves. The differential pressure identified by Delta P ranges from 20-50 psig and is simply an allowance made so that when the fluid is unloaded from the casing to the depth of the valve, the casing pressure will remain higher than the tubing pressure so that gas can enter the tubing. Otherwise, a zero pressure differential would exist and no gas would flow into the tubing for gas-lift induced production. This phenomenon is known in the industry as a stymie condition.
Referring now to FIG. 13, which also shows gas-lift calculations in accordance with the prior art, fluid above the uppermost valve is being aerated to the surface (lower density) by injecting gas from the annulus into the tubing. Note the shift of the zero GLR curve to the left (lower pressure) above Valve #1 by the addition of gas (dashed line) while fluid continues to be trnasferred from the casing to the tubing through the lower valves. The illustration of FIG. 13 identifies the instant when the second valve is uncovered but prior to gas entering the tubing at this point.
To satisfy the force balance requirement for unloading, Valve #1 must remain open to aerate the column of fluid from that point to the surface until Valve #2 is uncovered and gas starts entering the tubing at this point. When gas starts entering the tubing at the second valve, Valve #1 should close and remain closed. Therefore, Valve #'s 1 and 2 are spaced in accordance with maximum operating pressure. Whereas the set pressure of Valve #1 is also based on the operating pressure, the set pressure of Valve #2 is based on the reopening pressure of Valve #1. At this point, the conventional gas-lift design theory becomes quite critical. It is essential that an upper valve must not reopen for any reason while lifting from a lower valve. If this happens, valve interference will typically occur and it is quite likely that no further unloading will occur.
After the reopening pressure of valve #1 is established, this reopening pressure is then utilized in order to properly space Valve #3 in relation to Valve #2. It should be borne in mind that Valve #1 must remain closed while Valve #2 remais open during unloading operations until such time as Valve #3 is uncovered and gas begins to enter the tubing through Valve #3. At this point, if properly designed, Valve #2 should close and remain closed with gas entering the tubing only through open Valve #3. The next step in the design calculation concerns calculation of the reopening pressure (OP) of Valve #1 so as to establish proper spacing to Valve #3 and establish the set pressure of Valve #2. FIG. 14 is a graphical representation reflecting the detail of Valve 1 and 2. The dashed line represents the early theory that as gas begins to enter the tubing at Valve #2, casing pressure drops to the closing pressure (Pvc) of Valve #1 and there is a momentary increase in the density of the fluid flowing past Valve #1 with a resultant increase in pressure represented by Ptmax. The minimum pressure (Ptmin) occurs when the minimum gradient is once more achieved by the addition of more gas. The procedure then was to calculate the test rack opening pressure (Pvo) based on the minimum tubing pressure (Ptmin) and the reopening pressure (OP) based on the maximum pressure (Ptmax) since this would be the actual pressure available for unloading to Valve #3.
The following equations were derived for this purpose: ##EQU2##
After the bellow charge at well temperature (Pbt) was determined and then converted to 60.degree. F., the test rack opening pressure, i.e. the pressure determined by means of a test fixture into which the gas-lift valve is received, is calculated by the following equation: ##EQU3##
The temperature at each valve depth are then estimated by reference to a chart identifying the flowing temperature gradient for different flow rates, geothermal gradients and tubing sizes. A chart of this nature is illustrated on Page 12-3 of a P.I. Paper No. 926-4-S. Corrections to a temperature of 60.degree. F. may be accomplished by reference to a chart having correction factors. In the alternative, calculations can be accomplished using information obtained from charts for nitrogen charged bellows. The flowing temperature estimates were based on the maximum rate expected and it was assumed that a lesser rate would not affect the design.
After calculating the valve test rack opening pressure at 60.degree. F. in accordance with Equation 4, calculations were then made to achieve spacing of Valve #3 in relation to Valve #2. With reference to FIG. 15, the reopening pressure of Valve #2 was calculated in accordance with the following equations: ##EQU4##
The reopening pressure (OP.sub.2) was then plotted similar to the plot of OP, in accordance with FIG. 15 to determine the set pressure of Valve #3.
The minimum gradient technique was in wide use in the gas-lift industry until development of a technique referred to as the "optiflow" method which for the first time introduced the concept of employing "decreasing gradients" at each successively deeper valve of the gas-lift system. A similar fluid valve design is discussed on Pages 17-30 of the Macco gas-lift design manual pertaining to continuous flow installations relating to tubing sensitive valves. Other manufacturing organizations developed similar techniques through utilization of gas-lift valves that are considered highly tubing sensitive, but in all known cases the flowing temperatures were based on the maximum flow rate. Thus, valve interference remained a significant problem that resulted in the failure of many wells to be produced at the maximum production rate of the well. As mentioned above, when gas-lift valve interference develops, the liquid column within the well is not unloaded to the desired operating depth and the gas-lift system involved simply establishes a production rate that is substantially less than the maximum production rate of the well. Moreover, well production is also limited in many cases by a phenomenon typically referred to as "slugging." In this case the liquid column within the tubing is not properly serated and lightened in oder that it can be lifted efficiently to the surface. This improper aeration causes the liquid within the well to be forced to the surface in slugs or increments by the gas. Of course, much of the production fluid is retained by the surface tension of the tubing and descends back down through the tubing to a lower level where it again forms with other liquid as a slug or increment that is raised with gas.
In order to eliminate the problems of slugging and failure to unload to the desired operating level, gas-lift valve designs incorporating spring loaded, fluid operated valves were introduced. Utilization of spring loading rather than bellows operation rendered such valves insensitive to temperature. This method was highly successful in solving problems involving slugging and failure to properly unload to the desired operating level as in the case of the minimum gradient and optiflow techniques.
Early in the development of bellows charged gas-lift valve mechanisms, the design techniques were based upon accomplishment of valve closure by decreasing the pressure within the casing. It was subsequently determined, however, that any bellows charged casing pressure operated valve could be closed by simply reducing the tubing pressure to a predetermined pressure level. This meant that any valve could be used in conjunction with the "decreasing gradient" technique contrary to the then supposed design criteria that a particular kind of bellows charged gas-lift valve must be used. Although a number of design problems were overcome by innovations in pressure handling and valve design, there remained severe problems from the standpoint of temperature. Even though the gas-lift design techniques first assumed a constant flow rate with increasing gas-liquid ratios, it became more desirable to design for decreasing flow (liquid) rates instead. Again, there was the general assumption that estimating the high temperatures that would occur at each valve level represented the most conservative and safest approach for the design of gas-lift installations.
Obviously, laborious calculations were involved when gas-lift systems were designed in accordance with Equations 2 and 3 above. In order to simplify the design of gas-lift installations, many companies in the industry chose to accomplish design simplification by utilizing arbitrary drop in reopening pressures and thereby simplify the calculations involved in the design. In fact, some companies accomplished simplicity of design calculations without considering pressure drop at all but depended on the use of larger valve ports (higher tubing effect) in order to accomplish closure of the valves. These efforts toward simplicity of design calculations seemed to be an effort toward standardization and simplification of design techniques in order that the design of gas-lift systems could be "cook-booked" with minimum effort without unusual sacrifices from the standpoint of production.
One attempt to simplify gas-lift design took the form of an attempt to combine Equations 3 and 4 above and derive a temperature correction factor (Ct) chart in order that only one calculation step would be required in order to convert from down hole conditions to test rack opening pressure. The equation derived is as follows: EQU Pvo=[Pc@L+Pt@L(TEF)]Ct Equation 5.
Where:
Pvo=Test rack opening pressure at 60.degree. F., psig PA1 Pc@L=Reopening pressure at depths, psig PA1 Pt@L=Minium tubing pressure at depth, psig PA1 TEF=Tubing effect factor, percent PA1 C.sub.t =Temperature correction factor, no units
From the graphical standpoint, a representation of the typical "decreasing gradient" design takes the form illustrated in FIG. 16. With reference to FIG. 16, the arbitary drop in reopening pressure varies from 10 psig for a 600 psig system to 30 psig for a 1,000 psig system. This "decreasing gradient" design technique is in wide use at the present time as is the "minimum gradient" technique described above for accomplishing design of gas-lift systems. Under circumstances where the particular production characteristics of the well closely correlate to the simplified design techniques that are presently utilized, the production of these wells is quite good. In many cases, however, these conventional design techniques fail to develop a gas-lift system that achieves production at the maximum capability of the well involved. For example, where gas-lift systems are designed in accordance with Equation 5, as depicted in FIG. 16, the geothermal temperatures at the level of the various gas-lift valves can become critical. With the technique shown to FIG. 16, the lower rate at each successively deeper valve often results in decreasing temperatures, which in turn means that two or more valves may be set at the same pressure. Compensation for this undesirable characteristic can sometimes be provided by an increase in port size of the various valve but, to do so, often introduces other problems that result in inefficiency of production. Ideally, the purpose of the "decreasing gradient" technique is to provide pots of accurate size in the valve primarily for the purpose of eliminating slugging. A solution that was suggested for correction of this problem is to revert to the previously used method of establishing 25 psig drops in test rack opening pressures regardless of the particular design characteristics called for at each level within the well. To do so, however, might result in an overall increase in productivity from the well but, this sort of arbitrary design would in effect result in forcing the well to conform to the nature of the equipment rather than tailoring the equipment in accordance with the conditions of the well itself. One attempted solution to the temperature problem resulting from design characteristics in accordance with Equation 4 was to provide a spring loaded casing pressure operated valve thereby overcoming the temperature sensitivity of conventional bellows type gas-lift valve mechanisms. However, the high spring rate of such valves which did not allow full opening was not considered to provide an effective solution to the temperature problem.
All of the known gas-lift design techniques to date, where temperature is considered for purposes of correction, provide temperature correction factors that consider only the maximum temperature that is expected at the level of a particular valve. In accordance with the teachings of the present invention, it is a primary feature to provide a technique for designing a gas-lift system that compensates or corrects for the lowest temperature that could be encountered at an upper valve while lifting from a lower valve.
The proposed method involves a variation and improvement of the standard equation 5 wherein the equation form is as follows: EQU PREO@L=Pc@L=(Pvo/Ct)-Pt@L(TEF) Equation 5A.
Where PREO@L=Reopening pressure at depth corrected to the actual temperature at the valve, psig.
It is also a feature of this invention to provide a novel gas-lift design technique wherein the high and low temperatures that might be encountered are predicted at the level of each valve.
An even further feature of this invention concerns the provision of a novel technique for designing gas-lift systems wherein the test rack opening pressures (Pvo) are based on the highest temperature possible at each valve whereas the reopening pressures for spacing lower valves are based on the lowest temperature possible at each valve.
It is an even further feature of this invention to provide a novel technique for designing gas-lift systems wherein the reopening pressures that are utilized for the purpose of spacing the next lower valve of any particular gas-lift system is based on the lowest predicted temperature that might be encountered at a particular valve.
Among the several features of this invention is noted a novel design technique for gas-lift systems wherein the reopening pressures (low temperature) are then utilized as the maximum operating pressure available at the next lower valves in a gas-lift system.
A further feature of the gas-lift design technique of this invention is to provide a means for adjusting test rack opening pressures and spacing of gas-lift valves so that the installation can perform efficiently over a wide range of conditions (mainly temperature variations) without the necessity for redesign. A further feature of this invention is to provide a novel technique for designing gas-lift systems that effectively eliminates excessive gas usage due to valve interference that ordinarily results when upper valves reopen and inject gas into the tubing, thus resulting in insufficient pressure for unloading to lower valves.
It is also a feature of this invention to provide a novel technique for designing gas-lift systems to prevent slugging which causes an excessively high pressure in the tubing and which in turn reduces production.
One of the more important features of this invention is to provide a novel technique for designing gas-lift systems that avoid abnormally wide valve spacing that can otherwise render the installation inoperative.